Separation system to separate phases of downhole fluids for individual analysis

ABSTRACT

An apparatus for sampling a fluid in a borehole may include a vessel configured to be disposed in a borehole and at least one sensor in communication with one phase of the plurality of phases in the vessel. The vessel separates the fluid into a plurality of phases.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is claims priority from U.S. Provisional PatentApplication Ser. No. 61/485,961, filed on May 13, 2011, the disclosureof which is incorporated herein by reference in its entirety.

FIELD OF THE DISCLOSURE

This disclosure pertains generally to investigations of undergroundformations and more particularly to systems and methods for evaluatingdownhole fluids.

BACKGROUND OF THE DISCLOSURE

Commercial development of hydrocarbon fields requires significantamounts of capital. Before field development begins, operators desire tohave as much data as possible in order to evaluate the reservoir forcommercial viability. While data acquisition during drilling providesuseful information, it is often also desirable to conduct furthertesting of the hydrocarbon reservoirs in order to obtain additionaldata. Therefore, after a borehole for a well has been drilled, thehydrocarbon zones are usually tested with tools that acquire fluidsamples, e.g., liquids from the formation. These fluids may bemulti-phase fluids; i.e., fluids that are a mixture of water,hydrocarbons, and/or solids. The multi-phase nature of these fluids mayreduce the accuracy of evaluation of a particular phase.

In one aspect, the present disclosure addresses the need to separate oneor more phases of a downhole fluid.

SUMMARY OF THE DISCLOSURE

In one aspect, the present disclosure provides an apparatus for samplinga fluid in a borehole. The apparatus may include a vessel configured tobe disposed in a borehole, the vessel being further configured toseparate the fluid into a plurality of phases without substantiallyaffecting a structure of at least one of the separated phases; and atleast one sensor in communication with one phase of the plurality ofphases in the vessel.

In another aspect, the present disclosure provides a method for samplinga fluid in a borehole. The method may include separating the fluid intoa plurality of phases in a vessel positioned in the borehole withoutsubstantially affecting a structure of at least one of the separatedphases; and estimating a parameter of interest relating to at least onephase separated from the fluid while the at least one phase is in thevessel.

Examples of certain features of the disclosure have been summarizedrather broadly in order that the detailed description thereof thatfollows may be better understood and in order that the contributionsthey represent to the art may be appreciated.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed understanding of the present disclosure, reference shouldbe made to the following detailed description of the embodiments, takenin conjunction with the accompanying drawings, in which like elementshave been given like numerals, wherein:

FIG. 1 shows a schematic of a centrifugal-type of separator according toone embodiment of the present disclosure;

FIG. 2 shows a schematic of a thermal separator according to oneembodiment of the present disclosure; and

FIG. 3 shows a schematic of a separator that uses reactive surfacesaccording to one embodiment of the present disclosure;

FIG. 4 shows a schematic of a membrane-based separator according to oneembodiment of the present disclosure;

FIG. 5 illustrates a schematic of a formation evaluation system thatincludes a separator according to one embodiment of the presentdisclosure.

DETAILED DESCRIPTION

In aspects, the present disclosure relates to devices and methods toevaluate downhole fluids. As used herein, the term downhole fluid isgenerally any fluid found in a drilled wellbore and/or any fluid thatresides in the formation. Downhole fluids include but are not limitedto, naturally occurring fluids such as oil, gas, and water, as well asengineered fluids such as drilling fluids and surface injected fluids.The teachings may be advantageously applied to a variety of systems inthe oil and gas industry, water wells, geothermal wells, surfaceapplications and elsewhere. Merely for clarity, certain non-limitingembodiments will be discussed in the context of hydrocarbon producingwells.

Referring initially to FIG. 1, there is schematically illustrated oneembodiment of a test tool 100 that may be used to actively separate afluid into two or more homogeneous materials or phases (e.g., a polarphase, a nonpolar phase, an aqueous phase, a liquid hydrocarbon, a gashydrocarbon, water, etc.). As discussed in further detail below, theseparation may be performed without substantially affecting a structureof one or more of the substances making up the several phases. That is,after the separation, one or more than one of the separated phases stillretains the same molecular structure as prior to the separation (e.g.,minimal molecular dissolution or association). Of course, a minimalamount of change may be encountered in the post-separated phase, but notto a degree that affects the ability to use the post-separated phase toacquire information relating to that phase prior to separation. Thus,the pre-separation and post-separation phases are structurally similar.

The tool 100 may be used to evaluate one or more characteristics of theseparated phase(s) and also estimate one or more parameters relating tothe separation process (e.g., pressure, temperature, etc.). The tool 100may include an inlet 102 through which a fluid 103 enters an activeseparation chamber 104 and outlets 106 a,b through which the separatedphases 107 a,b exit the separation chamber 104. The tool 100 may includea variety of sensors configured to estimate one or more desiredparameters. For example, a sensor 108 a may be used to estimate acharacteristic of a first phase component (e.g., oil), and a sensor 108b may be used to estimate a characteristic of a second phase component(e.g., water). Other phase components (e.g., condensates) may beevaluated with similar sensors (not shown). Also, sensors 108 c may beused to estimate one or more environmental parameters (e.g., pressure,temperature, rotational speed, fluid flow rate, fluid velocity, etc.).In embodiments, the test tool 100 may include a separator 110 that usesrotation to separate the fluid into two or more phase components. Theseparator 110 may include an enclosure 112, which may be drum-shaped,that is rotated by a suitable motor 114.

During operation, the fluid 103 flows via the inlet 102 into theenclosure 112, which is rotated by the motor 114. The centrifugal forcesgenerated by the rotating enclosure 112 separates phases based onrelative density. In other embodiments, the separation may be performedindependent of orientation. As shown, the relatively lighter phase 107 a(e.g., oil) separates and exits via outlet 106 a and the relativelydenser phase 107 b (e.g., water) separates and exits via outlet 106 b.

Further, in some embodiments, the enclosure 112 may be oriented to allowgravity to also separate the phases based on relative density. Forexample, the tool 100 may include an orientation sensor (not shown) thatprovides an indication of verticality and an orientation device (notshown) that orients the device such that more dense phases collect at aparticular location in the chamber 104.

In conjunction with the separation process, the sensors 108 a-c maygenerate information relating to one or more parameters of the fluid103, the separated phase components 107 a,b and/or the environmentalconditions associated with the tool 100. ‘Information’ may be data inany form and may be “raw” and/or “processed,” e.g., direct measurements,indirect measurements, analog signal, digital signals, etc. It should beappreciated that the information provided by the sensors 108 a,b isindicative of a state, condition, or property of the separated phaseimmediately after separation, but before the separated phase has exitedthe tool 100. Also, the sensors 108 c may provide information relatingto the conditions under which the separation occurred. Thus, in aspects,the tool 100 may provide information that includes at least a propertyof one or more separated components and the conditions that caused theseparation.

The sensors 108 a,b may be configured to generate information regardingthe chemical composition(s) or material properties(s) of the separatedphases 107 a,b. This information may relate to properties that include,but are not limited to, one or more of: (i) pH, (ii) H₂S, (iii) density,(iv) viscosity, (v) thermal conductivity, (vi) electrical resistivity,(vii) chemical composition, (viii) reactivity, (ix) radiofrequencyproperties, (x) surface tension, (xi) infra-red absorption, (xii)ultraviolet absorption, (xiii) refractive index, and (xiv) rheologicalproperties.

The separation of the phase components may be performed by a number ofdifferent devices and techniques in addition to the centrifugalseparator shown in FIG. 1. For example, the tool 100 may include acyclonic separator wherein the fluid 103 is spun in a spiral orhelix-like manner in the chamber 104. Still other non-limitingembodiments of separators are discussed below.

Referring now to FIG. 2, there is shown a thermal separator 120 thatincludes a distillation column 122. In some embodiments, cooling devicessuch as thermoelectric elements 124 a,b may be used to remove heat fromthe fluid 123 in the column 122. A thermoelectric elements 124 a,b maybe formed of a suitable material (e.g., bismuth telluride) that whenenergized by an electrical circuit 126 transfers heat across a spaceagainst a temperature gradient (or Peltier effect). A suitable powersource 128 may provide electrical power. In other embodiments, heat maybe applied by suitable heating elements to separate phases in thedistillation column 122. In addition to or instead of thermalseparation, electrostatic forces may be used to separate phasecomponents based on the electric charge of the components. As discussedpreviously, sensors 108 a-c may be used to obtain desired informationrelating to the fluid and/or environment in the distillation column 122.

Referring now to FIG. 3, there is shown a column 140 that includes oneor more reactive column surfaces 142 that define a flow conduit 144where the separator 140 is used for chromatographic purposes, e.g., highperformance liquid chromatography, ion exchange chromatography,hydrophobic interaction chromatography, gel filtration chromatography,and combinations thereof. Chromatography is used to separate phases of aliquid. The liquid, i.e., the mobile phase, is poured or dripped througha column surface 142, i.e., the stationary phase. The column surfaces142 may interact with a targeted phase of the fluid 146. As the fluid146 flows along the column surface 142, the targeted phase of the fluid146 interacts with the column surface 142 and is retained by the columnsurface 142, which allows the remainder of the fluid 146 to continueflowing through the column 140. Thus, the targeted phase of the fluid146 is separated from the remainder of the fluid 146. Chromatography maybe used by designing the column surfaces 142 to interact with the fluid146 based on dipole-dipole interactions, ionic interactions or moleculesizes. As discussed previously, sensors 108 a-c may be used to obtaindesired information relating to the fluid and/or environment in the flowconduit 144.

For example, the column surfaces 142 may attract oil or water (e.g.,lipophilic, hydrophobic, hydrophilic), cause a phase component tocoalesce, and/or cause a desired flow regime. For instance, the surfacesmay be a combination of hydrophilic and superhydrophobic surfaces thatallow water to coalesce and then flow along a predefined channel.Similar combination of surface may be designed using oleophilic andoleophobic surfaces. In embodiments, the column surfaces 142 may beconfigured to operate according to HPLC (high performance liquidchromatography). HPLC is generally an automated system having fluidsapplied in a precise manner with controlled flow rates at highpressures. The column surfaces 142 may be a matrix of speciallyfabricated glass or plastic beads coated with a uniform layer ofchromatographic material. HPLC allows for high speed, high resolution,and reproducibility of the separation.

The column 140 may also be configured for ion exchange chromatographywhere oppositely charged molecules are bound to the column surfaces 142to allow a targeted phase to be separated from the fluid 146. Forexample, if the targeted phase is water to be separated from the fluid146, charged or ionic molecules would be bound to the column surfaces142. Water would bind to the ionic molecules and the remainder of thefluid 146 would flow through the column 140.

The column 140 may also be configured for hydrophobic interactionchromatography where the column surfaces 142 are impregnated withnonpolar groups. The nonpolar groups may interact with the hydrophobicphase of the fluid 146, which causes the hydrophobic phase to bind tothe column surfaces 142 and allows the charged phase to flow through thecolumn 140. An embodiment of this may include the oil phase beingseparated from the fluid 146, so that the remainder of the fluid 146flows through the column 140.

The column 140 may be configured for size exclusion chromatography wheremolecules are separated according to the size and/or shape of themolecules within the targeted phase of the fluid 146. In this instance,the column surface 142 may have gel beads with pores of a specified sizerange. The pores may retain molecules of a particular wettability, sizeand/or shape of the fluid 146. For example, as is known, an oil moleculeis size-wise larger than a water molecule. Thus, the pores of the columnsurfaces 146 may be configured to be penetrable by water but relativelyimpenetrable by oil. Such a column surface 142 then would retain waterbut allow the oil to flow through the column 140.

Referring now to FIG. 4, there is shown a separator 160 that includes apermeable material 162 that separates a chamber 164 into apre-separation section 166 and a post-separation section 168. In oneembodiment, the material may be a membrane 162 that has a permeabilityselected to allow passage of only a selected phase component (e.g., ahydrocarbon). A piston 170 or other suitable movable member reduces thevolume in the pre-separation section 166 to generate a pressuredifferential that forces the selected phase component through themembrane 162 and into the post-separation section 168. In otherembodiments, a vacuum pump (not shown) may be used to reduce pressure inthe post-separation section 168. In other embodiments, the material 162may be beads, or a sponge-like material. As discussed previously,sensors 108 a-c may be used to obtain desired information relating tothe fluid and/or environment in the membrane separator 160. Otherembodiments of using membrane separation may use pistons or otherpressurizing mechanisms to force the fluid through a membrane whichselectively filters molecules. The membrane may be porous, micro-porous,or nano-porous.

It should be appreciated that the above illustrative separationtechniques separate the phases without substantially affecting astructure of one or more of the substances making up the several phases.Separation processes involving pressure reduction below bubble point orcooling can cause condensate to in a liquid. However, the liquid and/orthe condensate in those processes may undergo a chemical structuralchange that may make it difficult or impossible to acquire informationrelating to the fluid prior to such a separation process. The separationtechniques of the present disclosure, however, retain the pre-separationstructure of phase substance(s) even after separation.

The teachings of the present disclosure may be used in a variety ofsurface and sub-surface applications. Merely for convenience, there isshown in FIG. 5, a tool configured to characterize a fluid that isconfigured for sub-surface applications. FIG. 5 schematicallyillustrates a wellbore system 10 deployed from a rig 12 into a borehole14. While a land-based rig 12 is shown, it should be understood that thepresent disclosure may be applicable to offshore rigs and subseaformations. The wellbore system 10 may include a carrier 16 and awellbore tool 20. Merely for ease of discussion, the wellbore tool 20 isshown as a fluid analysis tool. The fluid analysis tool 20 may include aprobe 22 that contacts a borehole wall 24 for extracting formation fluidfrom a formation 26. Extendable pads or ribs 28 may be used to laterallythrust the probe 22 against the borehole wall 24. The fluid analysistool 20 may include a pump 30 that pumps formation fluid from formation26 via the probe 22. Formation fluid travels along a flow line to one ormore sample containers 32 or to line 34 from which the formation fluidexits to the borehole 14. The fluid may have one or more pre-existingphase components (i.e., that exist prior to separation). The tool 20 mayinclude a separator 100 as described previously to separate one or morephase components from the fluid extracted from the formation 26. Aprogrammable controller may be used to control one or more aspects ofthe operation of the tool 20. For example, the wellbore system 10 mayinclude a surface controller 40 and/or a downhole controller 42.

In one mode of operation, the tool 20 is positioned downhole andoperated to extract fluid from the formation 26. The fluid from theformation (or formation fluid) may be a multi-phase fluid. Thus, theextracted fluid is conveyed to the separator tool 100. The separatortool 100 separates at least one phase from the extracted fluid.Referring now to FIGS. 1 and 5, during the separation phase, the sensors108 a,b estimate one or more phase properties of the separated phasesbefore the separated fluids have exited the separator tool 100. Thesensors 108 a,b provide information about the post-separated phase(s)that may be used to characterize the properties of the phases prior toseparation.

At the same time, the sensors 108 c acquire information that can be usedto evaluate the environmental conditions under which the phaseseparation occurred.

In some embodiments, the wellbore system 10 may be a drilling systemthat configured to form the borehole 14 using tools such as a drill bit(not shown). In such embodiments, the carrier 16 may be a coiled tube,casing, liners, drill pipe, etc. In other embodiments, the wellboresystem 10 may use a non-rigid carrier. In such arrangements, the carrier16 may be wirelines, wireline sondes, slickline sondes, e-lines, etc.The term “carrier” as used herein means any device, device component,combination of devices, media and/or member that may be used to convey,house, support, or otherwise facilitate the use of another device,device component, combination of devices, media and/or member.

The controller 40, 42 may include an information processor that is indata communication with a data storage medium and a processor memory.The data storage medium may be any standard computer data storagedevice, such as a USB drive, memory stick, hard disk, removable RAM,EPROMs, EAROMs, flash memories and optical disks, or other commonly usedmemory storage system known to one of ordinary skill in the artincluding Internet based storage. The data storage medium may store oneor more programs that when executed causes information processor toexecute the disclosed method(s). Signals indicative of the parameter maybe transmitted to a surface controller 40. These signals may also, or inthe alternative, be stored downhole in a data storage device and mayalso be processed. In one example, wired pipe may be used fortransmitting information.

The term “carrier” as used in this disclosure means any device, devicecomponent, combination of devices, media and/or member that may be usedto convey, house, support or otherwise facilitate the use of anotherdevice, device component, combination of devices, media and/or member.As used herein, the term “fluid” and “fluids” refers to one or gasses,one or more liquids, and mixtures thereof.

While the foregoing disclosure is directed to the one mode embodimentsof the disclosure, various modifications will be apparent to thoseskilled in the art. It is intended that all variations be embraced bythe foregoing disclosure.

1. An apparatus for sampling a fluid in a borehole, comprising: a vesselconfigured to be disposed in the borehole, the vessel being furtherconfigured to separate the fluid into a plurality of phases withoutsubstantially affecting a structure of at least one of the separatedphases; and at least one sensor in communication with one separatedphase in the vessel.
 2. The apparatus of claim 1, wherein the at leastone sensor comprises a plurality of sensors, each sensor being incommunication with a different phase of the plurality of phases.
 3. Theapparatus of claim 1, wherein the at least one sensor is configured togenerate signals representative of a parameter of interest relating tothe one phase.
 4. The apparatus of claim 1, further comprising anenvironmental sensor configured to estimate at least one environmentalparameter.
 5. The apparatus of claim 1, wherein the vessel includes aseparator separating the fluid into the plurality of phases.
 6. Theapparatus of claim 5, wherein the separator is configured to spin thefluid.
 7. The apparatus of claim 5, wherein the separator includes apermeable material configured to separate the fluid into the pluralityof phases.
 8. The apparatus of claim 5, wherein the separator includesat least one material configured to interact with one phase of theplurality of phases.
 9. The apparatus of claim 8, wherein theinteraction is one of: (i) attraction, (ii) repulsion, (iii) a molecularinteraction; (iv) chemical interaction, (v) physical interaction, and(vi) ionic interaction.
 10. The apparatus of claim 5, wherein theseparator changes a temperature of the fluid.
 11. The apparatus of claim1, wherein the one phase is selected from at least one of: (i) anaqueous phase, (ii) a hydrocarbon, (iii) a precipitate; (iv) a nonpolarphase, and (v) a polar phase.
 12. The apparatus of claim 1, wherein theone phase is selected from one of: (i) a solid, (ii) a liquid, and (iii)a gas.
 13. A method for sampling a fluid in a borehole, comprising:separating the fluid into a plurality of phases in a vessel positionedin the borehole without substantially affecting a structure of at leastone of the separated phases; and estimating a parameter of interestrelating to at least one separated phase fluid while the at least onephase is in the vessel.
 14. The method of claim 13, further comprisingestimating an environmental parameter while the fluid is beingseparated.
 15. The method of claim 13, wherein the parameter of interestis estimated while the fluid is being separated.
 16. The method of claim13, further comprising discharging the separated phases from the vesselafter estimating the parameter of interest.
 17. The method of claim 13wherein the fluid is separated by a chromatographic procedure.